Q2 2019 Earnings Call
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I would now like to turn the conference over to Gordon Penn Wire. Sir. Please go ahead.
Good morning, and thank you for joining our call today to discuss Chesapeakes financial and operational results for the 2019 second quarter.
Hopefully you've had a chance to review our press release and the updated investor presentation that we posted on our website. This morning.
During this morning's call, we will be making forward looking statements, which consist of statements that cannot be confirmed by reference to existing information, including statements regarding our beliefs goals expectations forecasts projections and future performance and the assumptions underlying such statements. Please know that there are number of factors that will cause actual results to differ materially from our forward looking statements, including the factors identified and discussed in our earnings release today and in other actually see filings.
Please recognize that except as required by applicable law, we undertake no duty to update any forward looking statements and you should not place any undue reliance on such statements. We may also reference to some non-GAAP financial measures, which help facilitate comparisons across periods, we thought and what peers for any non-GAAP measures. We use a reconciliation to the nearest corresponding GAAP measure can be found on our website and in our earnings release.
With me today on the call are Doug Lawler, Nick to walk, though and Frank Patterson.
Doug will begin the call and then turn the call over to Frank Nick for a review of our operational and financial results before we turn the teleconference over for Q1 night.
So with that thank you and I will now turn the teleconference over to Doug.
Thank you Gordon and good morning.
I'm pleased today to report Chesapeakes continued strategic progress in the second quarter featured increased oil production and enhanced capital efficiency, which continue to drive margin growth as we advance towards sustainable free cash flow, we're maximizing the value of our diverse portfolio through a returns focused capital allocation strategy and we are prudently managing our debt maturities to maintain future liquidity.
On the call today, you will hear references to our rate of change, which simply stated highlights the ongoing transformational improvements that are reflected in our past performance current business delivery and future value growth proposition.
You will also hear reference to our scale, which emphasizes the size strength and diversity of our portfolio.
Our scale provides the foundation for competitive and differential economic resource development.
You will also hear reference to our technical and operating capability, which combined with our scale and rate of change drive differential capital efficiency cash cost leadership and future growth.
During the quarter Chesapeake produced a record 122000 barrels of oil per day, and we increased our oil mix percentage to a record 25% total production. The oil volume increase is driven by the successful integration of our Brazos Valley asset steady growth from the powder River basin and improve based production performance from South, Texas and the mid continent.
Accordingly, we have raised the midpoint of our full year 2019 oil production guidance by approximately 250000 barrel.
Higher oil volumes and our focus on cash cost leadership yielded the highest second quarter margin per view, we in five years, we have lowered our full year guidance for production expense as well as gathering processing and transportation expense.
I'm very excited with the rapid progress we've made in our new Brazos Valley asset after only five months from closing we have a clearly defined plan to fully achieve the forecasted annual synergy savings of $250 million to $280 million per year.
We will continue to build upon the cash cost improvements and capital efficiencies identified notably we see further opportunity to the projected $600000 capital reduction realized on a per well basis as weve recognized up to $2 million in savings I'm certain well.
As a result of our capital efficiency, we have lowered the breakeven oil price for the Brazos valley, well to $39 per barrel and approximately 26% improvement.
Oil production is poised to increase during the second half of 2019.
We expect to turn in line approximately 170 oil wells in the Powder River Basin, South, Texas, and Brazos Valley assets, an increase of roughly 50% over the first half of 2019.
In a few moments Frank will share more with you on our asset level progress.
Capital spending for the quarter was in line with our guidance and we remain confident in our full year forecast. As reminder, we have downside protection for approximately 75% of our 2019 oil and gas volumes, we will continue to pursue pursue asset sales to further reduce debt.
Nick will share additional detail on our liquidity liability management and financial improvements for the quarter.
As noted in our earnings release in 2020, we expect to allocate more capital to oil growth areas with less capital going towards our gas assets as a result, with an approximately flat capital program to 2019, we project. Our 2020 oil volumes will show double digit percentage growth over 2019, while our gas volumes will show a double digit percentage decline.
Importantly, our projected adjusted EBITDAX remains approximately the same in 2019 levels using today's lower Nymex strip pricing and our current hedge position, we look forward to driving further value from our diverse portfolio and capital discipline in 2020 and beyond.
We will remain flexible and prudent with our capital allocation using our scale and operating efficiency to drive value in this volatile pricing environment I'm just excited about the future of Chesapeake energy and the value that we have to offer our employees leadership and board are driven and committed to achieving our strategic priorities of reducing our leverage metrics improving margins through continued oil growth and achieve achieving sustainable free cash flow from our portfolio of high quality assets.
Ill now turn the call to Frank for some further commentary on our oil growth and other operational achievements on the second quarter.
Thank you Doug good morning, everyone.
Let me start by commenting further on the significant capital efficiencies Weve already realized in Brazos Valley. The operating team continues to demonstrate the ability to rapidly changed outlook and performance profile of this asset Weve advanced the integration of Brazos valley into our portfolio and a rapidly moving into full development mode. We've demonstrated significant improvements across all aspects of the business units operations as Doug noted in his introduction, we've eliminated an average of over $600000 per well and a few wells. We've seen we've recognized over $2 million savings. These savings are as are the result of improved drilling and completion techniques faster cycle time, and lower oilfield service costs, but we're not done.
Just last week the completion team set a field frac crew record by pumping 15 stages, and placing 8.4 million pounds of sand in a single day. This accomplishment was aided by our operated sand mine, which has now supplying 100% of our sand needs for two frac crews.
On top of operational performance and cost savings. The team has also accelerate production performance by more than 30% with the average 2019 wells, reaching similar cumulative production.
In 180 days that historically took 260 days so far this year, we have turned in seven wells that have reached a maximum 24 hour production rate of more than 1000 barrels per day compared to just three that reach similar levels in 2018.
Additionally, we've increased workover activity and made a concerted effort to raise the field to Chesapeakes operating standards, which has already improved base production by more than 500000 barrels compared to our original projection for 2019.
Our subsurface understanding of the field was high when we completed the acquisition, but it's growing even stronger in recent months as the team has had a chance to gather additional data.
We've been able to leverage our reservoir technology lab and leave pvt data to greatly increase our understanding of fluid properties in the field as a result, we've shifted more than 230 locations into the black oil window of the play our understanding we will continue to evolve as we have recently taken to full course, which are now under evaluation in our core lab.
While there are many ways to measure how we've improved performance in this asset I am most proud of what the team has done to redefine the economics of the play at current strip prices. We have increased our two year per well cash flow projections by $1.3 million and as Doug noted since the acquisition, we've lowered to projected breakeven from $53 in 2018 to $39 today.
As we look forward to the rest of the year, 100% of our activity will be focused in the high margin oil window the Eagle Ford.
Our improved cycle times will allow us to accelerate our activity further and we anticipate placing approximately 45 oil wells online in the second half of the year compared to just 28 wells in the first half.
We anticipate continuing this trend in 2020, and currently forecast delivering 44 to 46 million barrels of oil production from a four rig drilling program Needless to say, we're excited to have Brazos Valley Chesapeakes oil portfolio and look forward to driving more value from the assets.
Ray of change is not restricted the Brazos Valley. This week, South, Texas drilling team delivered a 15361 foot measured depth, well and a tad over 5.5 days, averaging over 2700 feet per day.
Safe fast awesome results.
On the production front the team continues to deliver strong base volume performance. This was driven by adjusted adjusted well spacing enhanced completions and production optimization. The team also did a great job managing a planned third party plant outage that affected sales volumes in June .
As a result, we exceeded our internal production forecast for the quarter in the field South Texas continues to be a strong free cash flow generator for the company and our foundational asset.
In the powder River basin. The team continues to drive costs down and grow our margins, while remaining on target to deliver 100% year over year oil growth.
Our development plan in the Turner continues to evolve and the field. You are is moving lower as more wells are focused on the oil window.
Our central production facility came online in July and currently over 50% of oil volumes on pipe versus being truck.
We will continue to move more production to two pipeline and as a result, we expect to reduce GP into the per barrel of oil equivalent by more than 25% this year.
Approach operationally our cycle times continue to improve with the average spud to chill time expected to decrease approximately 25% year over year.
While we focused our.
Focused our attention on developing the Turner formation, we remain excited about the stacked pay potential under our acreage footprint.
We.
We recently drilled our first Niobrara wells.
Since 2014 and expect to report initial results from the next quarter. Additionally, the team continues their technical work on the Mowery formation and currently intend to drill the initial mowery chest and initial Mallory test in the volatile oil window later this year.
With the majority of our capital focused on high margin oil assets, we will lean on our core gas assets for efficient free cash flow delivery.
The Marcellus continues to generate significant free cash flow, while we maintain a disciplined capital spend the quality of Chesapeakes physician in the region is exceptional.
And our continued operating improvements driven by refined spacing longer laterals and optimize completion has significantly lowered our FMD costs and continued to yield improved recoveries per lateral foot.
With these improvements we've rapidly decreased our breakeven price as we look ahead at approximately 30 850 foot spacing and current rig pace. We have over 10 years of drilling inventory at a PV 10 breakeven price of between $1.50 and $1.75 per Mcf.
Overall Chesapeake continues to deliver progress along.
On the fronts that we can control operationally using our Geo technical and engineering expertise, we are seeing more opportunity across all basins Im confident that in the second half of the year the rate of change will continue.
With that I will turn the conference call over to Nick to review our financial performance.
Thank you Frank and good morning, everyone.
Driven by stronger adjusted oil production, an increase in our production mix towards oil and lower total cash operating expenses, we reported a 26% increase in adjusted EBITDAX margin per Boe compared to last year.
As we stated last quarter margin improvements, we're delivering are not simply due to price as realized prices before hedges.
Were lower compared to last year, primarily due to portfolio rotation and our intentional shift of capital toward higher margin oil production and away from drilling natural gas.
We improved our cash operating cost structure by approximately 57 million over the second quarter of 2018, primarily through lower GP into expenses.
Continuing the trend of optimizing our GP interest then we will be launching an RFP process for a new oil pipeline gathering agreement and brands Valley area. Shortly.
Moving our oil production to a gathering system should greatly reduce our current reliance on trucking mirabelle oil volumes.
Thereby improving our cost structure in the region.
In addition, we're also making progress towards solutions to help deliver our Brazos valley oil into the Gulf coast market, allowing us to take advantage of improved pricing versus Wi Fi.
We expect to have more to announce on this by the end of the 2019 third quarter.
In the PRB, we are connecting pads to our new oil gathering system every week and expect us to lower our oil gathering expenses in the field even further.
Finally, as Doug noted, we are allowing our gas volumes most specifically the haynesville production to fall in 2020 based on prudent capital allocation and this week gas price environment.
Our gathering contract in the Haynesville is an acreage dedication with no minimum volumes or other commitments. So we will see no gathering penalty from its volume drop.
We do have firm transportation out of North, Louisiana that we will not fully utilized at this reduced volume profile.
As a result, we forecast a net impact to our GP empty for the Haynesville region alone in 2020 versus 2019 of an absolute reduction of $79 million or an increase of just over three cents per mcf.
Production expenses rose during the second quarter due to a number of factors we've begun to improve our base production in brasses Valley, which resulted in higher year over year, workover activity and water disposal costs. Additionally, our AD valorem taxes increased due to higher property valuation assessments in Texas and in Wyoming.
We believe these anticipated onetime events and catch up expenses are mostly behind us. So we expect our Halloween per BOE, we need to come down both in the third and fourth quarters and accordingly, we have reduced our outlook range for full year 2019 production expense.
On the balance sheet side, our liquidity is strong as we entered ended the quarter with availability of.
Approximately 1.6 billion under our $3 billion Chesapeake credit facility and approximately 600 million under the $1.3 billion Brazos Valley credit facility.
We will retire in near term maturities through cash flow and future asset sales when market conditions are more conducive to refinance pending maturities, we will be prudent in doing so.
We currently have a couple of small portfolio cleanup asset divestitures underway and while we are optimistic that will yield positive outcomes, our liquidity position affords us the opportunity to be patient and hold off selling at the markets ultimately prove unattractive.
Finally, we have significant price protection through the end of this year and for a meaningful portion of 2020 expected production.
For the second half of 2019 over 75% of our forecasted 2019 oil production and natural gas production.
Is hedged with downside protection at average prices of $59.38 per barrel and $2.83 per Mcf respectively.
We also have approximately 265 bcf of gas and 15 million barrels of oil hedged at 276, and 59 93, respectively for 2020.
Additionally, we have locked in pricing for approximately 4 million barrels of our remaining Eagle Ford volumes in 2019 at a premium of approximately $5.85 to Wi Fi.
Operator, we'll now turn the call over for questions.
Thank you we will now begin the question and answer session.
To ask a question you May press Star then.
Keypad, if you are using a speakerphone please pick up your handset before pricing.
To address your question. Please press Star then too.
And our first question comes from Devin Mcdermott with Morgan Stanley . Please go ahead.
Good morning, Congrats on the very solid execution in the quarter.
Thanks, Joe.
My first question I wanted to hit in a bit more detail on the capital allocation strategy as you move into 2020, and I think as you laid it out the shift away from from gas over to oil makes a lot of sense and it definitely had some of the value of your portfolio diversity as well I wanted to dive into a bit more detail as you think about where you touched on the gas side and allocate more capital on the oil side.
What's some of the levers are that you have there would be you cut first sounds like Haynesville is pretty high on the list, but a bit more detail there would be useful.
Sure Devin I appreciate the question the the the focus of the company is obviously to drive where we can capture the greatest returns.
We are very fortunate to have extremely strong gas assets, which we have a lot of confidence in.
The breakeven in Marcellus is extremely low and very very competitive and we obviously still have.
John takeaway constraints out there that just with the infrastructure that exists in the northeast.
So that that remains one of the very top rate of return investments in our portfolio.
And we expect that production to remain relatively flat as it has for the past few years.
The oil assets the margin enhancement things that we're driving for with the free cash flow.
Sustainable free cash flow growth that we're targeting that's all going to be driven by the oil oil investments, notably the base and execution in South, Texas and then the growth in Brazos Valley in the powder River. So obviously that that leaves us with the Haynesville, which given current pricing in the flexibility we have will we will.
React accordingly, as we have reduced that activity substantially there.
Currently and forecast very low activity level with current pricing and if you see if we were to recognize.
Better prices in 2020, we will constantly evaluate that capital allocation and direct direct equity investments, where we can capture the best return.
That said, though the economics and the margins that were capturing from the oil investment make it difficult to see a lot of capital going back towards the Haynesville anytime in the near future. So.
Where we said it is basically a lot of strength with the Marcellus, we'll continue to monitor that.
That production level, there, but very pleased with the performance and execution in what we can deliver from that asset.
And the bulk of the capital as this year will be directed towards all the oil growth.
Got it that's very helpful and you also had some comments.
On potential further asset sales for deleveraging in it.
He also noted that given the capital efficiency improvements that you've seen so far there is a nice organic path to deleveraging over time, but as you think about the leverage targets and have further strategic action or asset sales might fit into achieving that overtime right a bit more detail and what would fit in those asset sales targets and what the opportunity set you see there is.
Sure David we have a very large portfolio producing assets and acreage and.
Probably don't want to go into a ton of detail on this call, but we're we're looking at a little bit acreage in northeast PA that.
It probably makes sense for us to consider divesting.
And a little bit acreage associated with the acquisition, we just made.
That.
It is not of our.
Primary drilling target.
Both both areas have great returns and that's the kind of acreage positions that inside of our portfolio.
We are choosing not to drill right now, but the return profile available to them as attractive and we believe therefore could be attractive to other producers in the market.
It is just a part of our strategy always to look.
Very carefully at our portfolio every year and think about what assets, we should continue down and what assets are rather inefficient for us to hold onto given the development profile that we have and so this is just part of that.
It it will be a nice tailwind to the.
Handling of near term maturities if that all plays out and if we decide that the market conditions are not attractive to move forward with those divestitures.
We can continue to hold them, it's really just a matter of whether or not the opportunity cost versus what's available in the market today makes sense to us.
And I might just add that add to it.
David I might just add on on top of Nick's comments there that.
It is our goal of deleveraging and when you look at the future of the company and we have a clear line of sight with the oil assets in the strength and quality of the portfolio to de lever organically as you said overtime. However, our focus is to accelerate that as quickly as possible and so whether it's non core small or even larger assets as market conditions dictate we will remain open and focused on that de leveraging.
Priority, which still remains our number one number one strategic priority so.
It's it's we've got a few things are in the works as Nick highlighted and we'll continue to look for opportunities to further de lever to accelerate that.
Deleveraging that we've described.
But it makes a lot of sense. Thank you very much.
Our next question comes from our Jayaram with Jpmorgan. Please go ahead.
Yes, good morning.
Perhaps this one is for Nick you showed some progress on the on the GE PMT a line item.
With the cost coming down.
In the powder River basin.
I was just wondering if you could.
Talk broadly about the portfolio and other opportunities.
To kind of lower your GP and take costs overtime.
Yes, absolutely.
So around you saw them, we talked a lot about last quarter, how we put in place the oil gathering.
Contract and the powder and Thats going to be a great contract for us we're going to get our all to market faster, we're going to get it to market more consistently well without regard to having to wait for truck traffic and so and things like that.
An inclement weather having oil on pipe is just a much more reliable form of delivery. In addition to that the cost to deliver.
Oil to a liquid either other transportation point or liquid sales market.
Deified is dramatically lower on a on a per barrel basis. We're doing this of course through a third party contract, where we don't spend any of our own capital.
We're going to look to do the same thing and Brad's Valley, we've had a number of midstream companies approach us.
Seeking a partnership there to go out and build that kind of a system similar to what we contracted for in the powder. So we'll undertake that RFP here in the near term.
There is more we can do across the portfolio of course, we think very actively about how to manage our portfolio of volumes as they grow around the way that we contract for our gathering processing transport. It is of course always about delivering the highest value hydrocarbon for the lowest cost. So I'll give you. An example of what I mean by that in the powder. We did also sign up for a little bit of incremental transportation that takes us from Guernsey.
To Cushing and in doing that.
We give ourselves more stability of pricing the pricing in the Guernsey market has held up pretty well you did see last winter there can be times, where the Guernsey market gets congested and so with this incremental transport out of basin, we feel like we have that pretty well covered so we'll pay a little bit for that transportation and believe that as well in the night.
To have that option.
Especially as we grow volumes there we will over run what we can feasibly sell in Guernsey on a regular basis.
Similarly in the breadth as valley, we're going to look to gain access to the Houston market and potentially the corporate market as well.
Looking at making sure we have direct access into the premium mph or LLS pricing structures that we utilize for our Eagle Ford barrels.
We believe that there are a couple of options that we have to do that and so we're.
We're moving down that path. So we will move away from trucking extensively in the field to gathering on pipe and then we will pay a little bit of transportation.
Incremental to what we do today to get from the field to the premium price point and then all in including the improvement in basis that we will realize we expect to have an overall more economic position.
I did note that in the Haynesville, we will see our gas volumes fall about that a little bit of pressure on the haynesville specific GP into next year.
That's something we'll continue to look at and see if there are any other opportunities there to optimize that spend and that ft that we committed to.
Back in 2010, and obviously, a very different world, but the pressure that we'll see in 2020 is pretty manageable.
And so we feel really good about the pretty obvious economic decision to pull back capital to the Haynesville in a time where gas prices are obviously.
Extremely weak and the Marcellus, we still maintain a very attractive gathering and transportation cost structure, we get access to very premium markets in the northeast, especially in the winter.
Our gathering cost in the northeast is extremely attractive relative to peers that is one place where we have a competitive standout position.
And we look to continue to leverage that it's part of what helps us recognize an extremely low breakeven as Frank pointed out and the northeast and it's what holds up our investment in an asset like that even in this time of very weak prices. So when we talk about gas falling year over year. We are very very much pointed to the haynesville. There we're going to do a pretty good job of maintaining our volumes in the Marcellus because the rate of return there is still pretty attractive even at these levels with our breakevens as low as we've gotten them.
And just about the eagleford those thanks for that commentary about some eagle Ford there.
Yes. So we continue to look at a number of things in the Eagle Ford both trying to consider alternatives for the gas gathering costs there that are.
On the high side of what we believe reflects the best situation. We could have in the market. Today of course, that's also a contract that's been in place for many years and was built out for a different time and a different set of economics.
And also on the oil takeaway are.
Growth activity in the Eagle Ford has really come to a place where we are generating free cash flow out of that asset and not really expecting that asset to grow volumes dramatically from here.
And so we're going to work with our transportation partners there to think about if there's any other ways to optimize that but.
Those are all things that are they are works in progress you can assume that in every basin. Our marketing team is hard at work every day trying to optimize how and where we're going to deliver our volumes and under what cost.
Great and just my follow up Nick is.
The.
The Capex is slightly tilted.
To to the first half of the year I mean, if you just take the midpoint of the range.
Roughly 53% of all your Capex in the first half 47 in the back half.
But youre tils or.
On the oil side more concentrated in the back half. So can you just help reconcile.
Thoughts on second half Capex given that mix.
Sure. So thats timing, if you think about what has to happen in order for our tilt scheduled to reflect what you see there is a.
Yeah, Theres a chart in our slides today to share that the largest number of tils occur in the third quarter in reality, the largest number of tils occur.
In.
Late August through late September and so in order to do that we've started spending money sooner than that and so you have more money that comes out in the first half than you do in the second half.
The cycle times on these assets or something that we think about often and always trying to.
Compress, but they are still.
Very real and so you spend money in May and June to be to start bringing wells online in August and September .
And the cycles that follow.
Thanks, a lot.
Our next question comes from Brian singer with Goldman Sachs. Please go ahead.
Thank you good morning.
Warm.
In in Brazos Valley can you add a little bit a little bit of color on the expansion of the black oil window can can you take us through the results that you saw from kind of well data that you saw from first quarter wells to 230 additional locations and then what you see as the upside versus downside risk to the economics of location as you get more data on decline rates from these first quarter wells.
Yes, Brian This is Frank Patterson.
So when we went through the acquisition, we kind of walk everybody through at that point. There were only three PV are four pvt samples for the entire field area. So we were kind of working with a limited amount of data.
So and the drilling program and not drilled several parts of the field and so we were we were kind of being very cautious and and conservative the way we viewed the the fluid windows as we've now dug into it and been able to go out and capture some pvt samples do some analysis and then we've drilled a few wells. What's happened is those wells that are in that 230 wells that have shifted that shifted from basically the the volatile oil condensate window to a black oil or relatively low would you or wind down.
So we have pretty high confidence and Matt because not only do we have pvt data, but we also have well performance data I think theres a map in the presentation that will that will demonstrate that.
We're seeing pretty high confidence of delivery across the footprint.
We are trying to describe that in one of the other maps that we put in the presentation that we've drilled across a big portion of the footprint now and seeing really good results, we're going to continue to extend that.
As as we go out and drill additional wells.
We're still trying to optimize the completion design here, where we're pumping less fluid.
Quite a bit of sand, which which we think is key but we are trying to eliminate some of the the fluid that we're pumping and getting.
A more complex fracture network around on around the Wellbores and we're still at a 1000 foot spacing. So that's the next step is what is the spacing really going to look like at the end of the day. We think it's between 750 and a 1000, we'll we'll know more about that after we get our core results. We have two cores that we've just taken and we took those scores across the Austin chalk.
Through the entire you for section so we're going to get a lot of good data here in the next.
A few months.
I think what you're going to see is our footprint is going to expand and I think we're going to see potentially some areas, where we can maybe tighten up on some spacing as well.
Great. Thank you and then my follow up is with regards to natural gas.
Both in the Haynesville and the Marcellus can you talk to any constraints on how long you can keep your rig count in the Haynesville It at zero and in the Marcellus to to keep production flat is there any point at which.
Hi, there any of the GP in tier mid stream becomes a constraint where you would otherwise either need to raise the rig count or want or need to to renegotiate contracts.
No there's really no constraint, Brian we do have ft. As I noted earlier and the 2020 impact of NFC is pretty muted it would grow a little bit over time as you saw.
Volumes continued to fall if you stated zero rigs I don't expect that we will stay at zero rigs forever I would think that at some point the gas market will begin to.
Look at some sort of a rebound here and come back some reasonable level, where the haynesville is more economic than it is today.
Yes, as you as you think about what our Breakevens are in the Haynesville.
They're not terrible and.
We're just using at the moment to think just as much about near term free cash flow as we are about long term rates of return and in a market where things might be a little bit more stable. There is long term rate of return here that we can access at prices that do not need to be north of $3. In fact, they can be well below $3 than we might choose to drill some more wells in the haynesville. So.
This is not a departure from the Haynesville forever by any stretch, but it is in the near term a recognition that with gas in the low $2 on the Brompton.
Falling in 2020 that.
It probably makes sense for us to focus on free cash flow more so for the for the immediate term I'll also note that our ft.
Begins to fall a little bit starting in 2021, and so as you do think about that long term profile.
It's pretty manageable.
The costs are real but again, we incorporated those and what I gave you earlier to note that the.
Gathering or the transportation costs all in for the Haynesville alone next year with the three cents pressure per Mcf. So we can digest that and then we can think about how we want to position. It for 2021, as we get into 2020 and and consider where we are great thing about the Haynesville of course is that when we get a price signal to to do so we can bring capital back and bring a lot of production online relatively quickly.
So there's there's no real penalty there other than just the ft that.
That.
Exists for quite a while but does get a little smaller starting in 2021, and then again another slice up down in 2022.
So as we think about.
The Marcellus on the other hand, we are maintaining relatively flat volumes, there and are always eager for a price signal that we can grow our volumes in the Marcellus.
At that with the confidence that we would see current pricing because.
As we all know the Marcellus is capable of a tremendous amount more volume from us and we just worry that if we over run the in basin markets, we would see prices collapse in a hurry. So we just try to balance what that demand looks like with the supply that we deliver.
And Brian just Frank I'll, just give a little more color Marcellus.
Just kind of think of it as a two to three rig program to maintain that two to three to four Bcf a day output.
It's probably the lowest activation costs and the gas world.
In the U.S. and.
Really capital efficient.
We're we're seeing a lot of dramatic changes in the <unk> because we're a lot were we have the footprint to allow us to drill longer laterals. So we can we can basically.
Drive the capital efficiency of that even higher.
The completion and the spacing.
Up and upgrading the space into a wider spacing is also paying huge dividends. So we're pretty pretty pleased with the Marcellus and as Nick said, that's a lever we can pull if the gas market allowed us to and so just think of that right. Now is kind of a steady state of two to three rigs going forward for a while.
Great. Thank you.
Our next question comes from Douglas with Bank of America. Please go ahead.
Thanks, Good morning, everybody. Thanks for taking my questions.
Doug I Wonder if I could just follow up on Brian's question and ask you the same in the Haynesville with Seadrill rigs what is the.
What is the underlying decline look like they have what would it take to stabilize the haynesville.
So it's a it's a great question and as you know the the.
Haynesville is a tremendous.
Tremendously productive asset.
And very very.
Dependent upon commodity prices and what we love is that.
The team there has done such a good job around capital efficiency and productivity and the.
The investment profile there is essentially at our discretion.
And as we look as Nick highlighted there I think it's very very very well said that when we look at 2020.
The decline in the current GPG commitments or not.
Significant enough that it says we're going to direct capital there to satisfy a GP anti obligation and so as we as we look out into 2021.
And beyond then we will continue to look at how we can best.
Maximize those those volumes to satisfy those legacy GPN t. commitments.
We also are excited about other opportunities in the Haynesville area, particularly in respect of the cotton Valley Con values.
An area that.
Horizon that has we have not actively invested in.
To my knowledge.
Here at Chesapeake and we have a great acreage position that we can continue to look for economic development there.
In the future so.
I think it's a it's a good question is something that we're not really that concerned about and we will direct capital there and make the best.
Investment decisions with the continued priority of of driving the greatest margins and achieving a sustainable free cash flow.
Appreciate the answer Doug My follow up is for Frank if I may and.
Trying be some there was a there are a couple of Colo wells here.
In the presentation Bell for in Brazos on auto CBB opened by the river.
Can you just talk about what's going on there because it was looked like dramatically better results than what you've guided towards I'm. Just wondering if there was something unusual about those or if we're starting to see.
You know what trend up into the right in terms of how you see the productivity of those areas.
Okay. Thanks for the question.
The bell for remember that that's a four well pad. So you have to you have to scale that down.
So thats in the in the black oil window, what that did was that well validated the work that we did.
On on Pvt analysis, and validated that the black oil window extends further down dip than we had really regionally thought.
We're still trying to get the optimum completion style on those wells.
So.
Doug Thats, a four well pad, so that looks really impressive, but it but you got to scale that back on the.
On the RC.
We highlighted that in our last call.
It's a.
It's a well up to the in the oil window of the Turner.
It's in an area where that we've got the spacing we think correct.
Well performance is really style in the north part of that field. If you. If you look at the entire oil window.
We've tried to demonstrate that in the graphic in that our average oil window wells are exceeding the peer.
Performance within the basin and to two of the wells to the north that we're highlighting that we talked about last time I had really high IP. Those wells are hanging in there and really outperforming what we're seeing is there is variability in the Turner.
And that was something that we expected. This is not a shale. This is a sandstone and I silty sandstone. So as we drill across the footprint, we're going to see a little bit of variability, but even with that variability, we're seeing really high rates of return.
On the mean well.
Understood appreciate the clarification, guys and great great quarter. Thanks.
Our next question comes from David Heikkinen with Heikkinen Energy. Please go ahead.
Good morning, guys.
I'm curious if you have any thoughts or expectation on the impact of oil realization in the Eagle Ford Brazos Valley premiums as Permian volumes get to the Gulf Coast.
The premiums contract and your expectation.
Yes, so the way we forecast that Dave is that we simply look at the same forward curves that you all do and there's a there's a curve for EMEA, which is our primary pricing point.
It certainly shows a contraction in so thats, how we build our economics.
As the U.S. continues to export oil.
We think that there's potentially the opportunity for us for some of that premium to to be sticky I, but we don't forecast anything beyond what the market tells us to expect today.
Okay. That's helpful and then as you talk through each asset Cpnt.
Ex the $79 million or three cents Haynesville, what do you think the run rate.
Should be for GP ante in the 2020.
Well, it's always a function yes. So it's it's not just a function of what the run rate for what the current rates are everywhere today, but also a function of.
The mix that we will see going forward and so.
You know as we refine capital allocation going into 2020 and we.
Refine our budget going into 2020, we would give everybody.
More specific guidance, but it should be.
Around where we see it today could be a little higher could be could be a little lower in dairy although.
I think we've done a pretty good job getting things down today.
We'll continue to work on other step changes that.
May present.
May present themselves to us but.
For now I'd say.
Until we until we have other renegotiations or new contracts that we would put in place.
We feel pretty good about our run rate.
Okay.
Thanks, Jeff.
Our next question comes from Charles Meade with Johnson Rice. Please go ahead.
Good morning, Doug and Nixon, Frank and the rest of the team there.
More Charles.
Thank you Frank I'd like to pick up on on.
One of your answers to an earlier question you were talking about that that bell pad that validated your.
Your view of the.
Of that black oil window, and you talked about how you're still trying to figure out the right way to complete those wells I'm curious.
Did you.
Very your completion and or you're you're landing zone across those four wells on that pad and if you're not generating that way how how should we look for you to.
IRET as you try to.
Triangulated on on the right recipe.
Yes, I think I think it's going to just come with more and more exposure Charles.
When we took over the asset.
We have to complete.
Some wells that had already been drilled that were already drilled by the previous operator. So we started in the first thing we wanted to do is get our logistics down and get our stage count up.
We've successfully done that the team has done a fantastic job is as I stated in the commentary.
What we're doing now is we're starting to look at as you say landing zones.
We're looking at the actual design and how much sand to put away.
We've reduced the amount of water, we're putting in the wells, which helps us both on.
The pump times as well as the flow back and handling fluid on the surface and so we're seeing a lot faster oil cuts on flow back. This is just going to evolve over time, we havent completed that many wells yet and as we complete more wells I think youre going to see that we're going to.
Start having an increase in productivity as we as we learn more and more about where to physically land the wells and.
Exactly how to treat all the wells.
There's there's a lot of knobs to turn and you just cant term all at the same time you have to slowly work your way through we're in the very very nascent stage of this development I think youre going to see this thing evolve a lot like South, Texas, where we get the spacing the.
Completion design, all optimized in pretty short order.
From from Oh, and away from natural gas, but wonder if you could talk about how you're arriving at the total level of capex that that you're you're choosing because it looks to me like you.
It looks like up another.
Meaningful outspend versus 2020 cash flows at least at the current strip and so.
Maybe could you guys talk about your thought process. If it makes sense in terms of what is what is obligated capex perhaps to hold.
Your your lease position together and you keep plays and then and then maybe perhaps the next piece of the stack would be.
The the work that you have to do to.
Optimize your development plan along the lines, what Frank was just talking about or how do you guys stack up the pieces to arrive at that at that total to two level.
And then also the.
We really don't have an obligated capex.
Or a lease expiration or commitment that obligations to a particular capital level as we think about our capital allocation flexibility that we've achieved over the past several years, we we have tremendous flexibility and how we choose our our capex.
Program, where we direct those investments.
As we think about how we generate the greatest value given any particular asset decline given the margins that were trying to capture given the free cash flow development, how we optimize the any via the company over time.
We will have ACA rigorously evaluate each of the investments and what is is great and I love is that we have a tremendous amount of flexibility the capital efficiencies that have been driven into our program have resulted in lower breakevens.
We've seen as Frank highlighted in some detail there that each each of the asset areas. The rate of change we've accomplished results in greater productivity and greater capital efficiency and so the the we're not projecting a meaningful outspend in 2020.
And we will continue to.
Evaluate pricing and the economics, and how we best optimize.
The capital investment in the productive the production over over that near term are one to two year window. We also continue to look at.
That hedging we haven't provided the guidance out there, but we've established some meaningful hedges for 2020.
And we're confident in our ability to continue to perform and achieve our strategic metrics.
Thank you for that color Doug.
Only thing I would add to that Charles is that.
We think about where we want to be long term, which is obviously to be free cash flow positive.
We want to be there in a way that is sustainable and so the investments we're making today are generating very strong returns.
And as long as that is true.
We will continue to make those investments so that we can get to a level of cash flow that will be sustainable I prices fall much further than what will re look at that as Doug noted, we have that flexibility and that is something that with a diverse portfolio of assets that have.
Some of them have extremely low breakeven cost all the way through gas in the Haynesville today, which is.
Certainly at a level that that pressure is its economics.
We have because it's a competitive strength for us to be able to pick and choose where we.
Spend our capital and make sure that we are earning a great rate of return on every well that we drill and if we're doing that and we will continue to invest in our program and build shareholder value. If we are not the net capital will come down it's pretty much as simple as that.
Got it thanks.
And our next question comes from Josh Silverstein with Wolfe Research. Please go ahead.
Yes. Thanks. Good morning, guys just wanted to build on that last last question there.
Would you do would you think sustainable free cash flow would come in 2021, and I guess, Doug from your comments do you guys do expect to be free cash flow was negative next year.
Just doing I guess some of the math that you put out there if you take the 255 EBITDAX from from this year hold it flat roughly $700 million of of interest expense, that's roughly $1.5 billion versus the capex spending of around two two so should we be thinking that the outspend is less than that so I just wanted to clarify those comments.
Yeah sure Josh No we have not provided guidance for next year.
That obviously pricing makes a big impact on that and as we look we are obviously going to be driving towards being free cash flow positive just absolutely as quickly as possible and I think that the the best thing to do is to look at the rate of change of what Weve accomplished in the productivity of our wells continued improvement in our capital efficiency.
And we are definitely not saying that we're going to be.
Have an outspend next year because of as Nick highlighted we have a tremendous amount of flexibility in our capital allocation and so the key is what he said and I'll reiterate is that.
We have great flexibility our program were tremendous assets, we will continue to adjust.
And look for.
Opportunities to further improve our productivity and capital efficiency and we will continue to.
Look at asset sales and how we can best manage the portfolio for long term value and.
The progress that we've made up to this point in time gives us tremendous.
Flexibility and options going forward and so.
I think that the best thing to look at is that the rate of change in the stability. That's in our company and program today, we'll continue to build upon that in 2020 2021, we'll be pursuing that positive free cash flow just as quickly as we possibly can with a tremendous portfolio that we have.
Got it thanks for that and then just understanding the two times leverage target that you want to get into based on where you guys are right now it's it's almost double that.
Is the goal to de lever through EBITDA growth fast faster or is it asset sales that will get you guys down faster.
It's both and it will be as rapidly as we possibly can and what makes the most sense for our.
Long term value creation story, but there's no question that that the strength and quality of the portfolio that we can do that organically with the with the growth that we expect.
From our oil assets and we will continue to monitor look for opportunities with small and potentially bigger assets sales to accelerate that.
Yes.
Our next question comes from Kashy Harrison with Simmons Energy. Please go ahead.
Hi, Good morning, everyone and thank you for taking my question.
So just want to one quick one from me Frank in the press release, you highlighted 10 years of inventory remain in the Marcellus at your current spacing assumptions I was just wondering if you could give us some color on how we should think about.
Economic inventory in in years across your major.
Your major regions, including the Eagle for the PRB vein build the Midcon, India and the Brazos Valley.
Okay Kashi.
So we were trying to describe kind of the core of the Marcellus Theres a lot more inventory there that's economic than than what is stated that's that's the the dollar 50 to $1.75 breakeven.
Locations. So that's only a partial.
Available inventory to us.
In Eagle Ford and we can talk about Brazos Valley Browses Valley, We're just getting started.
We have a lot of locations available to us.
Today.
We're still trying to understand exactly how big the break even the low the low breakeven window is it looks to be quite large.
So I would say you have multiple years that the four rig program and the inventory it really depends on how many rigs you want to throw at it we could accelerate Brazos valley. If we so desire I think four rigs as a really good run rate for us operationally.
And in South, Texas, we have less runway there, we probably have three or four years that add in the lower Eagle Ford, but then we have the Austin chalk and the upper Eagle Ford, which we'll tag onto that.
So it's it's getting to its probably one of our more mature assets.
In Gulf Coast in the.
In the Haynesville, we have years of inventory.
And if we have got a low rig count, which we will be doing in the near term.
Zero to low rig count.
It's just going to extend.
Mid con Theres, a lot of different players available to us in the mid con.
The issue with the mid Con is that Theres not one large plants. It's a bunch of discrete plays but theres thousands of locations available to us if we wanted to push that lever. The nice thing about the mid Con is it's a very oily basins. So theres a lot of.
Of oil opportunity there and in the powder. The Turner probably has another few years run rate at the current rig rig.
Deployment.
But then the Nio is basically across our entire footprint and is well over 1000 locations.
Mowery will be very similar that is as we move forward than we have apartments, Essex and other.
Formations available to us so we have.
We have long runway in every single one of our assets that will will be competitive in our portfolio.
All right that's it for me thank you.
Our next question comes from Neal Dingmann with.
Suntrust. Please go ahead.
Morning, guys. Thanks forgive me in.
Just a quick one per unit Thats, all about and I know you've done a great job of.
Accelerating the oil growth that some I'm looking how good healthy returns look for bolt bras those in the PRB. So I'm just thinking.
You want to de accelerating your are unsure you want to obviously lower the leverage.
And you're getting these type of returns would that consist of potentially increasing activity potentially.
Even more in those plays I'm, just wondering how you sort of balance the two.
You know I mean, given the de leveraging strategy and the the returns you're seeing in the especially in the PRB the Brazos.
Yeah sure Neal, we're very excited about it and encouraged by the capital efficiency and those productivity gains that were capturing and indeed that there are opportunities for us to potentially accelerate the balance that we have to look at in this portfolio given the.
The debt that we have in and incurring additional.
Costs, we just are very mindful of how we manage through this.
This this commodity volatility that we're seeing and so.
We will we will constantly evaluate the option there we see opportunities we can increase the rigs.
And both assets, but we are targeted on the most efficient.
Development plan that we can can possibly capturing and we're not going to react to just one one month or two months type of price.
Particularly on oil we're looking for the long term.
Making adjustments on the gas because of the greater macro issues that exist there and.
It's it's always an option, but at present, that's not something that we're we're.
Thinking about.
Okay. Thanks, and then they'll go ahead I'm sorry.
I'm sorry, this is Frank.
One thing to think about and I think we've spoken about this before but we're not going to sacrifice efficiency in our asset. So think of if you accelerate you have to accelerate both drilling and completion and lot aligned the two for what you don't want to do is go drill a bunch of wells and end up with docs and Fallon capital. So when you think about expanding in any play it might be more than one rig to match up with the completion crews.
No great Great add Frank and then just lastly, one quick one just Frank in the PRB with that wine rack test in the in the West what are you. What are you trying to get out of that and could that change plans on a go forward.
Yes, Neal that in the western part of our play we actually have the the Turner and the frontier kind of sitting on top of each other and it appears that there might be a frac barrier to between the two and we're trying to find a way to access the entire storage of those two systems. So it's kind of a combo task between a frontier in the Turner, which they're they're kind of genetically the same they just come there just a positive from different ends of the basin.
So.
We're testing that concept is that if that holds true and it works, you'll probably see additional wine racking on the west side of our field.
Very good thanks, guys.
Thank you.
Answer session I'd like to turn the conference back over to Doug Lawler for any closing remarks.
Yes. Thank you operator, we appreciate everyone joining us today just to reiterate months ahead, you'll continue to see Chesapeake execute on our priorities in driving change throughout all of our assets as we look to deliver record oil production record oil production mix in 2019, followed by the state had double digit oil growth that we expect on relatively flat capital in 2020 continue to be targeting improved margins as we increase our production.
Through lower GP, and T. and other cash costs.
And as we noted we will be.
Reducing our gas activity.
In forecasting double digit decline in gas in 2020 at current pricing.
We have a tremendous amount of confidence in our ability to continue with the momentum that we have and building on the rate of change. We've stated today with our scale and diverse portfolio and disciplined disciplined approach to allocating capital the highest return opportunities, we're very well positioned to deliver value for our shareholders. We thank you everyone for your time today and if you have any further questions. Please don't hesitate to reach out to us. Thank you.
The conference is now concluded. Thank you for attending today's presentation you may now disconnect.